Form 10-Q - Quarterly report [Sections 13 or 15(d)]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-Q


			☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2024


			☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-34776


Chord Energy Corporation (Exact name of registrant as specified in its charter)



Delaware						80-0554627
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1001 Fannin Street, Suite 1500
Houston, Texas						77002
(Address of principal executive offices)						(Zip Code)


(281) 404-9500 (Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock

CHRD

The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨

Number of shares of the registrant’s common stock outstanding at October 31, 2024: 61,130,474 shares.

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TABLE OF CONTENTS


			Page
Glossary of Terms			1
PART I — FINANCIAL INFORMATION			3
Item 1. — Financial Statements (Unaudited)			4
Condensed Consolidated Balance Sheets at September 30, 2024 and December 31, 2023			4
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2024 and 2023			6
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Nine Months Ended September 30, 2024 and 2023			7
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2024 and 2023			9
Notes to Condensed Consolidated Financial Statements			11



1. Organization and Summary of Significant Accounting Policies			11

2. Revenue Recognition			12
3. Inventory			13
4. Additional Balance Sheet Information			13
5. Fair Value Measurements			13
6. Derivative Instruments			15
7. Property, Plant and Equipment			18
8. Acquisitions			19
9. Divestitures and Assets Held for Sale			21
10. Investment in Unconsolidated Affiliate			22
11. Long-Term Debt			22
12. Asset Retirement Obligations			23
13. Income Taxes			23
14. Equity-Based Compensation			23
15. Stockholders’ Equity			25
16. Earnings Per Share			26
17. Commitments and Contingencies			27

18. Leases			27

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Overview and Recent Developments			31
Results of Operations			31
Liquidity and Capital Resources			38
Fair Value of Financial Instruments			41
Critical Accounting Policies and Estimates			41
Item 3. — Quantitative and Qualitative Disclosures About Market Risk			41
Item 4. — Controls and Procedures			42
PART II — OTHER INFORMATION			43
Item 1. — Legal Proceedings			43
Item 1A. — Risk Factors			43
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds			44

Item 5.— Other Information			44
Item 6. — Exhibits			44
SIGNATURES			46

GLOSSARY OF TERMS

The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:

“ABR.” Alternate base rate.

“ARO.” Asset retirement obligations.

“ASC.” Accounting Standards Codification.

“ASU.” Accounting Standards Update.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids or fresh water.

“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.

“Boepd.” Barrels of oil equivalent per day.

“Bopd.” Barrels of oil per day.

“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depreciation, depletion and amortization.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“ESG.” Environmental, social and governance.

“FASB.” Financial Accounting Standards Board.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“G&A.” General and administrative.

“GAAP.” Generally accepted accounting principles in the United States.

“GPT.” Gathering, processing and transportation.

“MBbl.” One thousand barrels of crude oil, condensate, natural gas liquids or fresh water.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“NGL.” Natural gas liquids.

“NYMEX.” The New York Mercantile Exchange.

“NYMEX WTI.” The New York Mercantile Exchange West Texas Intermediate crude oil price index.

“OPEC+.” The Organization of Petroleum Exporting Countries and other oil exporting nations.

“Plug.” A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

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“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved reserves.” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Reasonable certainty.” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“Reserves.” Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“SEC.” The U.S. Securities and Exchange Commission.

“SOFR.” Secured overnight financing rate as administered by the Federal Reserve Bank of New York.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Wellbore.” The hole drilled by the bit that is equipped for crude oil or gas production on a completed well. Also called well or borehole.

“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

EXPLANATORY NOTE

On May 31, 2024, Chord Energy Corporation (“Chord” or the “Company”) completed the previously announced arrangement agreement with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”) and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, the Company acquired Enerplus in a stock-and-cash transaction. The business combination was accounted for as of May 31, 2024 under the acquisition method of accounting in accordance with FASB ASC 805, Business Combinations. Accordingly, unless otherwise specifically noted herein, the periods prior to May 31, 2024 report the financial results of Chord excluding the impacts from the business combination with Enerplus, while the periods as of and subsequent to May 31, 2024 report the financial results including the impacts from the business combination.

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PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Chord Energy Corporation

Condensed Consolidated Balance Sheets (Unaudited)


	September 30, 2024		December 31, 2023

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	52,050	$	317,998
Accounts receivable, net	1,294,597		943,114
Inventory	77,460		72,565
Prepaid expenses	31,703		42,450
Derivative instruments	55,667		37,369
Other current assets	2,061		11,055
Current assets held for sale	38,598		—
Total current assets	1,552,136		1,424,551
Property, plant and equipment
Oil and gas properties (successful efforts method)	12,434,669		6,320,243
Other property and equipment	58,082		49,051
Less: accumulated depreciation, depletion and amortization	(1,797,305)		(1,054,616)
Total property, plant and equipment, net	10,695,446		5,314,678
Derivative instruments	30,987		22,526
Investment in unconsolidated affiliate	116,504		100,172
Long-term inventory	25,861		22,936
Operating right-of-use assets	48,653		21,343

Goodwill	539,793		—
Other assets	24,783		19,944
Total assets	$	13,034,163	$	6,926,150

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	68,386	$	34,453
Revenues and production taxes payable	769,540		604,704
Accrued liabilities	738,991		493,381

Accrued interest payable	11,839		2,157
Derivative instruments	3		14,209
Advances from joint interest partners	2,434		2,381
Current operating lease liabilities	40,138		13,258
Other current liabilities	27,704		916
Current liabilities held for sale	2,745		—
Total current liabilities	1,661,780		1,165,459
Long-term debt	867,173		395,902
Deferred tax liabilities	1,421,403		95,322
Asset retirement obligations	279,892		155,040
Derivative instruments	45		717
Operating lease liabilities	21,065		18,667
Other liabilities	5,891		18,419
Total liabilities	4,257,249		1,849,526

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	September 30, 2024		December 31, 2023

	(In thousands, except share data)
Commitments and contingencies (Note 17)
Stockholders’ equity
Common stock, $0.01 par value: 240,000,000 shares authorized, 66,772,383 shares issued and 61,479,508 shares outstanding at September 30, 2024; and 120,000,000 shares authorized, 45,032,537 shares issued and 41,249,658 shares outstanding at December 31, 2023	671		456
Treasury stock, at cost: 5,292,875 shares at September 30, 2024 and 3,782,879 shares at December 31, 2023	(732,263)		(493,289)
Additional paid-in capital	7,329,177		3,608,819
Retained earnings	2,179,329		1,960,638
Total stockholders’ equity	8,776,914		5,076,624
Total liabilities and stockholders’ equity	$	13,034,163	$	6,926,150

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(In thousands, except per share data)
Revenues
Oil, NGL and gas revenues	$	1,121,012	$	840,625	$	2,771,841	$	2,302,251
Purchased oil and gas sales	329,455		282,743		1,024,567		629,705

Total revenues	1,450,467		1,123,368		3,796,408		2,931,956
Operating expenses
Lease operating expenses	247,055		177,115		582,908		489,077
Gathering, processing and transportation expenses	77,353		52,294		194,467		132,706
Purchased oil and gas expenses	329,622		281,615		1,021,739		627,433
Production taxes	100,973		72,485		244,410		191,490
Depreciation, depletion and amortization	360,214		160,293		757,036		431,131
General and administrative expenses	52,115		26,117		159,904		100,775
Exploration and impairment	7,269		1,611		14,908		33,257



Total operating expenses	1,174,601		771,530		2,975,372		2,005,869
Gain (loss) on sale of assets, net	(2,973)		899		13,814		3,739
Operating income	272,893		352,737		834,850		929,826
Other income (expense)
Net gain (loss) on derivative instruments	52,721		(85,205)		29,753		11,247
Net gain from investment in unconsolidated affiliate	1,089		13,512		23,246		21,421
Interest expense, net of capitalized interest	(19,146)		(7,923)		(38,946)		(22,286)
Other income (expense)	(2,657)		1,651		4,253		9,137
Total other income (expense), net	32,007		(77,965)		18,306		19,519
Income before income taxes	304,900		274,772		853,156		949,345
Income tax expense	(79,584)		(65,696)		(215,126)		(227,199)


Net income	$	225,316	$	209,076	$	638,030	$	722,146
Earnings per share:
Basic (Note 16)	$	3.63	$	5.01	$	12.61	$	17.28



Diluted (Note 16)	$	3.59	$	4.77	$	12.34	$	16.54


Weighted average shares outstanding:
Basic (Note 16)	61,802		41,563		50,388		41,670
Diluted (Note 16)	62,629		43,662		51,507		43,527

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited)


	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount

	(In thousands)
Balance as of December 31, 2023	41,250	$	456	3,783	$	(493,289)	$	3,608,819	$	1,960,638	$	5,076,624
Equity-based compensation and vestings	599	4		—	—		4,771		—		4,775
Tax withholdings on settlement of equity-based awards	(280)	(3)		—	—		(46,048)		—		(46,051)
Dividends	—	—		—	—		—		(137,541)		(137,541)
Share repurchases	(193)	—		193	(29,999)		—		—		(29,999)
Warrants exercised	175	2		—	—		8,015		—		8,017
Net income	—	—		—	—		—		199,353		199,353
Balance as of March 31, 2024	41,551	459		3,976	(523,288)		3,575,557		2,022,450		5,075,178
Shares issued in Arrangement	20,680	207		—	—		3,731,930		—		3,732,137
Equity-based compensation and vestings	139	1		—	—		5,359		—		5,360
Tax withholdings on settlement of equity-based awards	(61)	—		—	—		(11,306)		—		(11,306)
Dividends	—	—		—	—		—		(124,708)		(124,708)
Share repurchases	(365)	—		365	(61,747)		—		—		(61,747)
Warrants exercised	287	1		—	—		12,874		—		12,875
Net income	—	—		—	—		—		213,361		213,361
Balance as of June 30, 2024	62,231	668		4,341	(585,035)		7,314,414		2,111,103		8,841,150

Equity-based compensation and vestings	11	—		—	—		5,918		—		5,918
Tax withholdings on settlement of equity-based awards	(3)	—		—	—		(622)		—		(622)
Dividends	—	—		—	—		—		(157,090)		(157,090)
Share repurchases	(951)	—		952	(147,228)		—		—		(147,228)
Warrants exercised	192	3		—	—		9,467		—		9,470
Net income	—	—		—	—		—		225,316		225,316
Balance as of September 30, 2024	61,480	$	671	5,293	$	(732,263)	$	7,329,177	$	2,179,329	$	8,776,914

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	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount

	(In thousands)
Balance as of December 31, 2022	41,477	$	438	2,249	$	(251,950)	$	3,485,819	$	1,445,491	$	4,679,798
Equity-based compensation and vestings	210	2		—	—		11,852		—		11,854
Tax withholdings on settlement of equity-based awards	(77)	(1)		—	—		(10,299)		—		(10,300)
Dividends	—	—		—	—		—		(204,884)		(204,884)
Share repurchases	(111)	—		111	(15,003)		—		—		(15,003)
Warrants exercised	39	—		—	—		276		—		276
Net income	—	—		—	—		—		296,999		296,999
Balance as of March 31, 2023	41,538	439		2,360	(266,953)		3,487,648		1,537,606		4,758,740
Equity-based compensation and vestings	64	2		—	—		15,325		—		15,327
Tax withholdings on settlement of equity-based awards	(22)	—		—	—		(3,331)		—		(3,331)
Dividends	—	—		—	—		—		(137,507)		(137,507)
Share repurchases	(209)	—		209	(30,815)		—		—		(30,815)



Warrants exercised	19	—		—	—		1,085		—		1,085


Net income	—	—		—	—		—		216,071		216,071
Balance as of June 30, 2023	41,390	441		2,569	(297,768)		3,500,727		1,616,170		4,819,570



Equity-based compensation and vestings	12	—		—	—		10,081		—		10,081
Tax withholdings on settlement of equity-based awards	(1)	—		—	—		(192)		—		(192)
Dividends	—	—		—	—		—		(58,374)		(58,374)
Share repurchases	(703)	—		703	(112,504)		—		—		(112,504)
Warrants exercised	675	7		—	—		73,350		—		73,357
Net income	—	—		—	—		—		209,076		209,076
Balance as of September 30, 2023	41,373	$	448	3,272	$	(410,272)	$	3,583,966	$	1,766,872	$	4,941,014

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended September 30,
	2024		2023

	(In thousands)
Cash flows from operating activities:
Net income	$	638,030	$	722,146
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	757,036		431,131

Gain on sale of assets	(13,814)		(3,739)
Impairment	9,838		28,964
Deferred income taxes	146,882		176,678
Net gain on derivative instruments	(29,753)		(11,247)
Net gain from investment in unconsolidated affiliate	(23,246)		(21,421)
Equity-based compensation expenses	16,053		37,260

Deferred financing costs amortization and other	6,407		1,072
Working capital and other changes:
Change in accounts receivable, net	(19,112)		(258,175)
Change in inventory	(6,937)		(4,945)
Change in prepaid expenses	8,090		430
Change in accounts payable, interest payable and accrued liabilities	70,538		135,880
Change in other assets and liabilities, net	(29,240)		42,483
Net cash provided by operating activities	1,530,772		1,276,517
Cash flows from investing activities:
Capital expenditures	(877,381)		(642,584)
Acquisitions, net of cash acquired	(652,672)		(361,609)
Proceeds from divestitures	21,788		46,002

Derivative settlements	(17,760)		(203,238)

Proceeds from sale of investment in unconsolidated affiliate	—		40,612
Contingent consideration received	25,000		—
Distributions from investment in unconsolidated affiliate	6,914		8,499
Net cash used in investing activities	(1,494,111)		(1,112,318)
Cash flows from financing activities:



Proceeds from revolving credit facilities	2,250,000		135,000
Principal payments on revolving credit facilities	(1,780,000)		(135,000)

Cash paid to settle Enerplus senior notes	(63,000)		—
Deferred financing costs	(3,313)		—


Repurchases of common stock	(239,804)		(157,122)
Tax withholding on vesting of equity-based awards	(57,979)		(13,823)
Chord dividends paid	(437,725)		(394,652)


Payments on finance lease liabilities	(1,242)		(1,398)
Proceeds from warrants exercised	30,454		74,611

Net cash used in financing activities	(302,609)		(492,384)
Decrease in cash and cash equivalents	(265,948)		(328,185)
Cash and cash equivalents:
Beginning of period	317,998		593,151
End of period	$	52,050	$	264,966

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	Nine Months Ended September 30,
	2024		2023

	(In thousands)
Supplemental non-cash transactions(1):
Change in accrued capital expenditures	$	42,306	$	77,091
Change in asset retirement obligations	3,869		1,057




Dividends payable	20,572		36,044

___________________

(1)Amounts exclude non-cash consideration transferred and balances acquired on May 31, 2024 in respect of the Arrangement (as defined in Note 1—Organization and Summary of Significant Accounting Policies). Refer to Note 8—Acquisitions for additional information.

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Organization and Summary of Significant Accounting Policies

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production company with quality and sustainable long-lived assets primarily located in the Williston Basin.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2023 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement of the Company’s financial position, have been included. Management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Annual Report”).

Enerplus Arrangement

On February 21, 2024, the Company entered into an arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, the Company agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”). Enerplus was an independent North American oil and gas exploration and production company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The transaction was effected by way of a plan of arrangement under the Business Corporations Act (Alberta). The Arrangement was completed on May 31, 2024.

In connection with the Arrangement, the Board of Directors of Chord unanimously (i) determined the issuance of the shares of common stock, par value $0.01 per share, of Chord (the “Chord Stock Issuance”), and the amendment of Chord’s restated certificate of incorporation to increase the number of authorized shares of common stock from 120,000,000 to 240,000,000 shares of common stock (the “Chord Charter Amendment”) are fair to, and in the best interests of, Chord and the holders of common stock, (ii) approved and declared advisable the Chord Stock Issuance and Chord Charter Amendment and (iii) recommended that the holders of common stock approve the Chord Stock Issuance and Chord Charter Amendment.

Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock (the “Share Consideration”) and $1.84 per share in cash (the “Cash Consideration” and together with the Share Consideration, the “Arrangement Consideration”) in exchange for each share of Enerplus they owned at closing.

The Arrangement has been accounted for under the acquisition method of accounting in accordance with the FASB ASC 805, Business Combinations (“ASC 805”). Chord was treated as the acquirer for accounting purposes. Under the acquisition method of accounting, the assets and liabilities of Enerplus have been recorded at their respective fair values as of the acquisition date on May 31, 2024. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after May 31, 2024. See Note 8—Acquisitions for additional information.

Risks and Uncertainties

As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond the Company’s control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and the prices for crude oil, NGLs or natural gas may be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGL and natural gas reserves that may be economically produced, the assessment of goodwill impairment, and the Company’s access to capital.

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Significant Accounting Policies

Goodwill. In accordance with FASB ASC 350, Intangibles - Goodwill and Other, goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually on October 1 or whenever events or changes in circumstances indicate that the fair value of the reporting unit may have been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying amount exceeds the fair value, an impairment loss is recognized for that excess amount. Circumstances that could indicate impairment and require the Company to assess for impairment include, but are not limited to, declines in the Company’s share performance coupled with adverse commodity prices. Unfavorable changes to these factors, or others, could result in goodwill impairment in future periods. Any such charge will not affect the Company’s cash flow from operating activities or liquidity.

Other than the item disclosed above, there have been no material changes to the Company’s significant accounting policies and estimates from those disclosed in the 2023 Annual Report.

Recent Accounting Pronouncements

In November 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”). This standard clarifies that single reportable segment entities are subject to the disclosure requirements under Topic 280 in its entirety. This ASU is effective for fiscal years beginning after December 15, 2023 and interim periods within those fiscal years beginning after December 15, 2024. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.

In December 2023, the FASB issued ASU 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” to expand the disclosure requirements for income taxes, specifically relating to the effective tax rate reconciliation and additional disclosures on income taxes paid. The Company expects to adopt this ASU effective January 1, 2025, and the adoption is not expected to affect the Company’s financial position or results of operations, but will result in additional disclosures.

In March 2024, the SEC released its final rule on climate-related disclosures, requiring the disclosure of certain climate-related risks, management and governance practices, and financial impacts, as well as greenhouse gas emissions. Large accelerated filers will be required to incorporate the applicable climate-related disclosures into their filings for annual reporting periods beginning in fiscal year 2025, with additional requirements relating to greenhouse gas emissions effective for annual reporting periods beginning in fiscal year 2026. In April 2024, the SEC paused implementation of the final rule pending the resolution of consolidated legal challenges that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. The Company is currently evaluating the impact of this rule on its financial statements and related disclosures.

2. Revenue Recognition

Revenues from contracts with customers were as follows for the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

	(In thousands)
Crude oil revenues	$	1,073,933	$	775,969	$	2,600,888	$	2,074,746
Purchased crude oil sales	320,692		269,619		994,059		584,109
NGL and natural gas revenues	47,079		64,656		170,953		227,505
Purchased NGL and natural gas sales	8,763		13,124		30,508		45,596

Total revenues	$	1,450,467	$	1,123,368	$	3,796,408	$	2,931,956

The Company records revenue when the performance obligations under the terms of its customer contracts are satisfied. For sales of commodities, the Company records revenue in the month the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. For the three and nine months ended September 30, 2024 and 2023, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

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3. Inventory

The following table sets forth the Company’s inventory balances for the periods presented:


	September 30, 2024		December 31, 2023

	(In thousands)
Inventory
Equipment and materials	$	36,032	$	30,201
Crude oil inventory	41,428		42,364
Total inventory	77,460		72,565
Long-term inventory
Linefill in third-party pipelines	25,861		22,936
Total long-term inventory	25,861		22,936
Total	$	103,321	$	95,501

4. Additional Balance Sheet Information

The following table sets forth certain balance sheet amounts comprised of the following:


	September 30, 2024		December 31, 2023

	(In thousands)
Accounts receivable, net
Trade and other accounts	$	1,027,894	$	749,356
Joint interest accounts	282,056		207,571

Total accounts receivable	1,309,950		956,927
Less: allowance for credit losses	(15,353)		(13,813)
Total accounts receivable, net	$	1,294,597	$	943,114

Revenues and production taxes payable
Royalties payable	$	390,892	$	297,531
Revenue suspense	330,023		266,704
Production taxes payable	48,625		40,469
Total revenue and production taxes payable	$	769,540	$	604,704

Accrued liabilities
Accrued oil and gas marketing	$	251,871	$	165,141
Accrued capital costs	221,994		122,260
Accrued lease operating expenses	144,309		107,606
Accrued general and administrative expenses	49,725		37,882

Current portion of asset retirement obligations	30,359		10,507
Accrued dividends	20,065		25,167
Other accrued liabilities	20,668		24,818
Total accrued liabilities	$	738,991	$	493,381

5. Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO and properties acquired in a business combination or upon impairment, at fair value on a non-recurring basis.

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Financial Assets and Liabilities

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:


	Fair value at September 30, 2024
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Commodity derivative contracts (see Note 6)	$	—	$	41,342	$	—	$	41,342
Contingent consideration (see Note 6)	—		45,312		—		45,312
Investment in unconsolidated affiliate (see Note 10)	116,504		—		—		116,504
Total assets	$	116,504	$	86,654	$	—	$	203,158
Liabilities:
Commodity derivative contracts (see Note 6)	$	—	$	48	$	—	$	48
Total liabilities	$	—	$	48	$	—	$	48


	Fair value at December 31, 2023
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Commodity derivative contracts (see Note 6)	$	—	$	11,312	$	5,877	$	17,189
Contingent consideration (see Note 6)	—		42,706		—		42,706
Investment in unconsolidated affiliate (see Note 10)	100,172		—		—		100,172
Total assets	$	100,172	$	54,018	$	5,877	$	160,067
Liabilities:
Commodity derivative contracts (see Note 6)	$	—	$	14,926	$	—	$	14,926
Total liabilities	$	—	$	14,926	$	—	$	14,926

Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s swaps and collars are valued by a third-party preparer based on an income approach. The significant inputs used are commodity prices, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company recorded a credit risk adjustment to reduce the fair value of its net derivative asset for these contracts by $0.6 million at September 30, 2024 and to increase its net derivative liability for these contracts by $0.5 million at December 31, 2023. See Note 6—Derivative Instruments for additional information.

Transportation derivative contracts. The Company had a buy/sell transportation contract as of December 31, 2023 that was a derivative contract for which the Company had not elected the “normal purchase normal sale” exclusion under FASB ASC 815, Derivatives and Hedging. This transportation derivative contract was valued by a third-party preparer based on an income approach. The significant inputs used were quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of this contract included certain market differential metrics that were unobservable during the term of the contract. Such unobservable inputs were significant to the contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the fair value hierarchy as of December 31, 2023. As of June 30, 2024, the term of this contract had expired. See Note 6—Derivative Instruments for additional information.

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Contingent consideration. In connection with the 2021 divestiture of certain oil and gas properties, the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI exceeds $60 per barrel for such year (the “Contingent Consideration”). If NYMEX WTI for calendar year 2024 is less than $45 per barrel, then the buyer’s obligation to make any remaining earn-out payments is terminated. The fair value of the Contingent Consideration is determined by a third-party preparer using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs used are NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. During the nine months ended September 30, 2024, the Company received $25.0 million related to the 2023 earn-out payment. See Note 6—Derivative Instruments for additional information.

Investment in unconsolidated affiliate. The Company owns common units in Energy Transfer LP (“Energy Transfer”) which are accounted for using the fair value option under FASB ASC 825-10, Financial Instruments. The fair value of the Company’s investment in Energy Transfer was determined using Level 1 inputs based upon the quoted market price of Energy Transfer’s publicly traded common units at September 30, 2024 and December 31, 2023. See Note 10—Investment in Unconsolidated Affiliate for additional information.

Non-Financial Assets and Liabilities

The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs.

Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.

Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate.

Enerplus Arrangement. On May 31, 2024, the Company completed the Arrangement with Enerplus. The assets acquired and liabilities assumed were recorded at fair value as of May 31, 2024. The fair value of Enerplus’ oil and gas properties was calculated using an income approach based on the net discounted future cash flows from the producing properties and related assets. The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, forecasted commodity prices (adjusted for basis differentials), operating and development costs, expected future development plans for the properties and the utilization of a discount rate based on a market-based weighted-average cost of capital. The Company also recorded ARO assumed from Enerplus at fair value. The inputs utilized in valuing the assumed ARO were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of May 31, 2024, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. In addition, the Company recorded goodwill as a result of the Enerplus Arrangement. Goodwill is subject to ongoing impairment evaluation as described in Note 1—Organization and Summary of Significant Accounting Policies—Goodwill. See Note 8—Acquisitions for additional information.

6. Derivative Instruments

Commodity derivative contracts. The Company utilizes derivative financial instruments to manage risks related to changes in commodity prices. The Company’s crude oil contracts settle monthly based on the average NYMEX WTI crude index price and its natural gas contracts settle monthly based on the average NYMEX Henry Hub natural gas index price.

The Company utilizes derivative financial instruments including fixed-price swaps and two-way and three-way collars to manage risks related to changes in commodity prices. The Company’s fixed-price swaps are designed to establish a fixed price for the volumes under contract. Two-way collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. Three-way collars are designed to establish a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) for the volumes under contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

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At September 30, 2024, the Company had the following outstanding commodity derivative contracts:


Commodity	Settlement Period	Derivative Instrument	Volumes			Weighted Average Prices
					Fixed-Price Swaps			Sub-Floor			Floor			Ceiling

Crude oil	2024	Two-way collars	1,840,000	Bbls								$	67.50		$	81.68
Crude oil	2024	Three-way collars	368,000	Bbls					$	55.00		$	71.25		$	92.14
Crude oil	2024	Fixed-price swaps	460,000	Bbls		$	73.82
Crude oil	2025	Two-way collars	4,378,000	Bbls								$	63.96		$	79.17
Crude oil	2025	Three-way collars	2,371,000	Bbls					$	52.69		$	67.69		$	82.14
Crude oil	2025	Fixed price swaps	362,000	Bbls		$	68.93
Crude oil	2026	Three-way collars	2,540,000	Bbls					$	51.78		$	66.78		$	79.89
Natural gas	2025	Two-way collars	1,380,000	MMBtu								$	3.00		$	4.18
Natural gas	2025	Fixed-price swaps	4,301,600	MMBtu		$	3.75
Natural gas	2026	Two-way collars	2,262,500	MMBtu								$	3.00		$	4.73

Subsequent to September 30, 2024, the Company entered into the following commodity derivative contracts:


					Weighted Average Prices
Commodity	Settlement Period	Derivative Instrument	Volumes		Fixed-Price Swaps		Floor		Ceiling

Crude oil	2025	Two-way collars	730,000	Bbls			$	65.00	$	76.62
Crude oil	2025	Fixed-price swaps	730,000	Bbls	$	71.87
Crude oil	2026	Two-way collars	730,000	Bbls			$	65.00	$	71.83

Transportation derivative contracts. The Company had contracts that provided for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming. The contracts had required the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreements. The Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion. As of June 30, 2024, the terms of these contracts expired. As of December 31, 2023, the estimated fair value of the remaining contract was $5.9 million, which was classified as a current derivative asset on the Company’s Condensed Consolidated Balance Sheet. The Company recorded the changes in fair value of these contracts to GPT expenses on the Company’s Condensed Consolidated Statements of Operations. Settlements on these contracts are reflected as operating activities on the Company’s Condensed Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable. See Note 5—Fair Value Measurements for additional information.

Contingent consideration. The Company bifurcated the Contingent Consideration from the host contract and accounted for it separately at fair value. The Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. As of September 30, 2024, the estimated fair value of the Contingent Consideration was $45.3 million, of which $24.6 million was classified as a current derivative asset, and $20.7 million was classified as a non-current derivative asset on the Condensed Consolidated Balance Sheet. As of December 31, 2023, the estimated fair value of the Contingent Consideration was $42.7 million, of which $22.6 million was classified as a current derivative asset and $20.1 million was classified as a non-current derivative asset on the Condensed Consolidated Balance Sheet. See Note 5—Fair Value Measurements for additional information.

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The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Condensed Consolidated Statements of Operations for the periods presented:


		Three Months Ended September 30,				Nine Months Ended September 30,
Derivative Instrument	Statements of Operations Location	2024		2023		2024		2023

		(In thousands)
Commodity derivatives	Net gain (loss) on derivative instruments	$	54,143	$	(91,483)	$	27,147	$	4,097
Commodity derivatives (buy/sell transportation contracts)	Gathering, processing and transportation expenses(1)	—		(1,432)		(5,877)		16,847
Contingent consideration	Net gain (loss) on derivative instruments	(1,422)		6,278		2,606		7,150

__________________

(1)The change in the fair value of the transportation derivative contracts was recorded in GPT expenses as a loss for the nine months ended September 30, 2024 and the three months ended September 30, 2023 and as a gain for the nine months ended September 30, 2023.

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheets.

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The following table summarizes the location and fair value of all outstanding derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheets:


		September 30, 2024
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount

		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — current assets	$	44,508	$	(13,414)	$	31,094
Contingent consideration	Derivative instruments — current assets	24,573		—		24,573

Commodity derivatives	Derivative instruments — non-current assets	33,877		(23,629)		10,248
Contingent consideration	Derivative instruments — non-current assets	20,739		—		20,739
Total derivatives assets		$	123,697	$	(37,043)	$	86,654

Derivatives liabilities:
Commodity derivatives	Derivative instruments — current liabilities	$	13,417	$	(13,414)	$	3

Commodity derivatives	Derivative instruments — non-current liabilities	23,674		(23,629)		45

Total derivatives liabilities		$	37,091	$	(37,043)	$	48

		December 31, 2023
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount

		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — current assets	$	20,647	$	(11,769)	$	8,878
Contingent consideration	Derivative instruments — current assets	22,614		—		22,614
Commodity derivatives (buy/sell transportation contracts)	Derivative instruments — current assets	5,877		—		5,877
Commodity contracts	Derivative instruments — non-current assets	16,760		(14,326)		2,434
Contingent consideration	Derivative instruments — non-current assets	20,092		—		20,092
Total derivatives assets		$	85,990	$	(26,095)	$	59,895

Derivatives liabilities:
Commodity derivatives	Derivative instruments — current liabilities	$	25,978	$	(11,769)	$	14,209
Commodity derivatives	Derivative instruments — non-current liabilities	15,043		(14,326)		717


Total derivatives liabilities		$	41,021	$	(26,095)	$	14,926

7. Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment:


	September 30, 2024		December 31, 2023

	(In thousands)
Proved oil and gas properties	$	11,433,840	$	6,220,766
Less: Accumulated depletion	(1,772,247)		(1,035,393)
Proved oil and gas properties, net	9,661,593		5,185,373
Unproved oil and gas properties	1,000,829		99,477
Other property and equipment	58,082		49,051
Less: Accumulated depreciation	(25,058)		(19,223)
Other property and equipment, net	33,024		29,828
Total property, plant and equipment, net	$	10,695,446	$	5,314,678

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8. Acquisitions

2024 Acquisition

On May 31, 2024, the Company completed the Arrangement with Enerplus and issued 20,680,097 shares of common stock and paid $375.8 million of cash to Enerplus shareholders. Also on May 31, 2024, and pursuant to the Arrangement Agreement, the Company (i) paid cash to settle Enerplus equity-based compensation awards, (ii) paid cash to satisfy and discharge in full the Enerplus credit facility and (iii) paid a cash retention bonus to Enerplus employees.

Preliminary purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Arrangement at their estimated fair value on May 31, 2024 of $4.1 billion. Goodwill recognized as a result of the Arrangement totaled $539.8 million, none of which is deductible for income tax purposes. Goodwill is primarily attributable to additional operational and financial synergies expected to be realized from the combined operations. Determining the fair value of the assets and liabilities of Enerplus requires judgement and certain assumptions to be made. See Note 5—Fair Value Measurements for additional information.

The tables below present the total consideration transferred and its preliminary allocation to the estimated fair value of identifiable assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date of May 31, 2024. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after May 31, 2024, which may result in a different allocation than that presented in the tables below. Certain estimated values for the acquisition, including oil and natural gas properties, intangibles and inventory, are not yet finalized and are subject to revision as additional information becomes available and more detailed analyses are completed.


	Purchase Price Consideration
	(In thousands)
Common stock issued to Enerplus shareholders(1)	$	3,732,137
Cash paid to Enerplus shareholders(1)	375,813
Cash paid to settle Enerplus equity-based compensation awards(2)	102,393
Cash paid to settle Enerplus credit facility(3)	395,000
Cash paid for retention bonus to Enerplus employees(4)	5,920
Total consideration transferred	$	4,611,263

__________________

(1)The Company issued 20,680,097 shares of common stock and paid $375.8 million of cash to Enerplus shareholders as Arrangement Consideration. Enerplus shareholders received, for each Enerplus common share issued and outstanding, 0.10125 shares of common stock as Share Consideration and $1.84 per share of cash as Cash Consideration. The fair value of the common stock issued was based on the opening price of the Company’s common stock on May 31, 2024 of $180.47. See Note 15—Stockholders’ Equity for additional information.

(2)Each Enerplus outstanding equity-based compensation award became fully vested upon completion of the Arrangement on May 31, 2024. See Note 15—Stockholders’ Equity for additional information.

(3)On May 31, 2024, the Company fully satisfied all obligations under the Enerplus credit facility, and the Enerplus credit facility was concurrently terminated. See Note 11— Long-Term Debt for additional information.

(4)In connection with the Arrangement, employees of Enerplus were paid a retention bonus upon the closing of the Arrangement totaling $5.9 million.

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	Preliminary Purchase Price Allocation

	(In thousands)
Assets acquired:
Cash and cash equivalents	$	239,921
Accounts receivable, net	281,492
Inventory	5,701
Prepaid expenses	16,323


Oil and gas properties (successful efforts method)	5,253,860
Other property and equipment	6,812
Long-term inventory	8,636
Operating right-of-use assets	42,954
Other assets	1,049
Total assets acquired	$	5,856,748

Liabilities assumed:
Accounts payable	$	1,965
Revenues and production taxes payable	199,706
Accrued liabilities	186,334
Current portion of long-term debt	60,063
Current operating lease liabilities	27,420

Deferred tax liabilities	1,179,200
Asset retirement obligations	115,056
Operating lease liabilities	15,534
Total liabilities assumed	$	1,785,278

Net assets acquired	$	4,071,470
Goodwill	539,793
Purchase price consideration	$	4,611,263

Post-arrangement operating results. The results of operations of Enerplus have been included in the Company’s unaudited condensed consolidated financial statements since the closing of the Arrangement on May 31, 2024. The following table summarizes the total revenues and income before income taxes attributable to Enerplus that were recorded in the Company’s Condensed Consolidated Statement of Operations for the periods presented.


	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024

	(In thousands)
Revenues	$	389,127	$	521,163
Income before income taxes	75,855		90,986

Unaudited pro forma financial information. Summarized below are the condensed consolidated results of operations for the periods presented, on an unaudited pro forma basis, as if the Arrangement had occurred on January 1, 2023. The information presented below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the Arrangement, including transaction costs incurred by the Company. In connection with the Arrangement, the Company incurred merger-related costs of $17.5 million and $80.3 million for the three and nine months ended September 30, 2024, respectively, which were recorded to general and administrative expenses on the Condensed Consolidated Statements of Operations. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Arrangement occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results. The pro forma results of operations do not include any future cost savings or other synergies that may result from the Arrangement or any estimated costs that have not yet been incurred by the Company to integrate the Enerplus assets.

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2023		2024		2023

	(In thousands, except per share data)
Revenues	$	1,555,282	$	4,397,893	$	4,073,263
Net income	307,127		812,294		904,039

Net income per share:
Basic	$	4.93	$	13.13	$	14.50
Diluted	4.77		12.89		14.08

9. Divestitures and Assets Held for Sale

2024 Divestitures and Assets Held for Sale

Assets held for sale. During the third quarter of 2024, the Company entered into an agreement to divest certain of its non-core properties located outside of the Williston Basin. The transaction closed on October 25, 2024 for estimated net cash proceeds (including purchase price adjustments) of $36.1 million. As of September 30, 2024, the Company classified the assets and liabilities associated with these properties as held for sale on its Condensed Consolidated Balance Sheet.

The following table presents balance sheet data related to the assets held for sale:


	September 30, 2024

	(In thousands)
Assets:
Oil and gas properties	$	39,367
Less: accumulated depreciation, depletion and amortization	(1,169)
Total property, plant and equipment, net	38,198
Inventory	357
Prepaid expenses	43
Total current assets held for sale	$	38,598
Liabilities:
Assets retirement obligations	$	1,587
Revenues and production taxes payable	1,158
Total current liabilities held for sale	$	2,745
Net assets	$	35,853

Other divestitures. During the three and nine months ended September 30, 2024, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $0.9 million and $21.3 million, respectively.

2023 Divestitures

Non-core properties. During the year ended December 31, 2023, the Company entered into separate agreements with multiple buyers to sell certain of its non-core properties located outside of the Williston Basin (the “Non-core Asset Sales”). As of December 31, 2023, the Company had completed these Non-core Asset Sales and received total net cash proceeds (including purchase price adjustments) of $39.1 million, subject to customary post-closing adjustments. As of December 31, 2023, the Company recorded a pre-tax net loss on sale of assets of $8.4 million for the Non-core Asset Sales and an impairment loss of $5.6 million to adjust the carrying value of the assets held for sale to their estimated fair value less costs to sell. The impairment loss was recorded within exploration and impairment expenses on the Condensed Consolidated Statements of Operations.

Other divestitures. During the year ended December 31, 2023, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million.

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10. Investment in Unconsolidated Affiliate

As of September 30, 2024 and December 31, 2023, the fair value of the Company’s investment in Energy Transfer was $116.5 million and $100.2 million, respectively, which represented less than 5% of Energy Transfer’s issued and outstanding common units. The carrying amount of the Company’s investment in Energy Transfer is recorded to investment in unconsolidated affiliate on the Condensed Consolidated Balance Sheet.

During the three and nine months ended September 30, 2024, the Company recorded a net gain of $1.1 million and $23.2 million, respectively, on its investment in Energy Transfer, comprised of an unrealized loss for the change in fair value of the investment of $1.2 million and an unrealized gain for the change in fair value of the investment of $16.3 million, respectively, and a realized gain for cash distributions received of $2.3 million and $6.9 million, respectively. During the three and nine months ended September 30, 2023, the Company recorded a net gain of $13.5 million and $21.4 million, respectively, on its investment in Energy Transfer, primarily comprised of an unrealized gain for the change in the fair value of its investment of $9.7 million and $10.8 million, respectively, and a realized gain for cash distributions received of $2.5 million and $8.5 million, respectively.

11. Long-Term Debt

The Company’s long-term debt consists of the following:


	September 30, 2024		December 31, 2023

	(In thousands)
Senior secured revolving line of credit	$	470,000	$	—
Senior unsecured notes	400,000		400,000

Less: unamortized deferred financing costs	(2,827)		(4,098)


Total long-term debt, net	$	867,173	$	395,902

Senior secured revolving line of credit. The Company has a senior secured revolving credit facility (the “Credit Facility”) among Oasis Petroleum North America LLC, the Company, Chord Energy LLC, Enerplus, the other guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent and issuing bank. The Credit Facility matures on July 1, 2027.

On May 31, 2024, the Company entered into the Fifth Amendment to Amended and Restated Credit Agreement (the “Fifth Amendment”). The Fifth Amendment, among other things, increased the borrowing base to $3.0 billion and increased the aggregate amount of elected commitments to $1.5 billion. On November 4, 2024, the Company (i) completed its semi-annual borrowing base redetermination, which affirmed the current borrowing base of $3.0 billion and the aggregate elected revolving commitment amounts of $1.5 billion and (ii) entered into the Sixth Amendment to Amended and Restated Credit Agreement (the “Sixth Amendment”). The foregoing description of the Fifth Amendment and Sixth Amendment does not purport to be complete and is qualified in its entirety by reference to the text of the Fifth Amendment and Sixth Amendment, copies of which are filed as Exhibit 10.1 and Exhibit 10.2, respectively, to this Quarterly Report on Form 10-Q. The next scheduled redetermination is expected to occur in or around April 2025.

At September 30, 2024, the Company had $470.0 million borrowings outstanding and $30.7 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $999.3 million. At December 31, 2023, the Company had no borrowings outstanding and $8.9 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $991.1 million.

During the three and nine months ended September 30, 2024, the weighted average interest rate incurred on borrowings on the Credit Facility was 7.51% for both periods. During the three and nine months ended September 30, 2023, the weighted average interest rate incurred on borrowings on the Credit Facility was 7.09% for both periods. The Company was in compliance with the financial covenants under the Credit Facility at September 30, 2024. The fair value of the Credit Facility approximates its carrying value since borrowings under the Credit Facility bear interest at variable rates, which are tied to current market rates.

Borrowings are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding loans at their respective interest rate plus a margin rate ranging between 1.75% to 2.75% for Term SOFR Loans and 0.75% to 1.75% for ABR Loans. In addition, Term SOFR Loans are also subject to a 0.1% credit spread adjustment. The unused borrowing base is subject to a commitment fee ranging between 0.375% to 0.500%.

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Senior unsecured notes. At September 30, 2024, the Company had $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “Senior Notes”). Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. As of September 30, 2024 and December 31, 2023, the fair value of the Senior Notes, which are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $400.8 million and $400.0 million, respectively.

Enerplus credit facility. Upon consummation of the Arrangement on May 31, 2024, the Enerplus credit facility was terminated, and the Company paid the remaining outstanding amount of $395.0 million to fully satisfy all such outstanding obligations that were owed under the Enerplus credit facility.

Enerplus senior unsecured notes. Upon consummation of the Arrangement on May 31, 2024, the Company assumed $63.0 million of 3.79% senior unsecured notes from Enerplus (the “Enerplus Senior Notes”). The Enerplus Senior Notes were recorded in the Condensed Consolidated Balance Sheet at their fair value acquired of $60.1 million as of the acquisition date. The fair value of the Enerplus Senior Notes, which represented a Level 2 fair value measurement, was estimated based on the amount that the Company would have to pay a third party to assume the debt, including the credit spread for the difference between the issue rate and the May 31, 2024 market rate. The May 31, 2024 market rate was estimated by comparing the debt to new issuances (secured or unsecured) and secondary trades of similar size and credit statistics for both public and private debt. On July 2, 2024, the Company repaid all of the remaining outstanding Enerplus Senior Notes of $63.0 million and the remaining accrued interest on such notes of $0.8 million.

12. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the nine months ended September 30, 2024 (in thousands):




Balance at December 31, 2023	$	165,546
Liabilities assumed in Arrangement	138,489
Liabilities incurred during period	2,721

Liabilities settled during period	(7,550)
Liabilities settled through divestitures	(269)
Accretion expense during period	11,307
Revisions to estimates	1,594
Liabilities held for sale	(1,587)
Balance at September 30, 2024	$	310,251

The Company’s ARO includes plugging and abandonment liabilities for its oil and gas properties in the United States and Canada. Accretion expense is included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations. At September 30, 2024, the current portion of the total ARO balance was $30.4 million and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

13. Income Taxes

The Company’s effective tax rate was 26.1% and 25.2% of pre-tax income, respectively, for the three and nine months ended September 30, 2024 as compared to an effective tax rate of 23.9% for the three and nine months ended September 30, 2023.

The effective tax rate for the three months ended September 30, 2024 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings. The effective tax rates for the nine months ended September 30, 2024 and the three and nine months ended September 30, 2023 were higher than the statutory federal rate of 21% primarily as a result of state income taxes.

On May 31, 2024, the Company completed the Arrangement, and as a result recognized a net deferred tax liability of $1.2 billion in its purchase price allocation as of the acquisition date primarily to reflect the difference between the tax basis and the fair value of Enerplus’ assets acquired and liabilities assumed. The Company did not record a Canadian deferred tax asset due to the lack of continued operations in Canada going forward.

14. Equity-Based Compensation

The Company has previously granted RSUs, PSUs and LSUs (each as defined below), as well as phantom unit awards under its equity compensation plans.

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Equity-based compensation expenses are recognized in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations. During the three and nine months ended September 30, 2024, the Company recognized $5.9 million and $16.1 million, respectively, in equity-based compensation expenses related to equity-classified awards. During the three and nine months ended September 30, 2023, the Company recognized $10.1 million and $37.3 million, respectively, in equity-based compensation expenses related to equity-classified awards. Equity-based compensation expenses related to liability-classified awards were not material for the three and nine months ended September 30, 2024 and 2023.

Pursuant to the Arrangement Agreement, at the effective time of the Arrangement, all Enerplus equity-based compensation awards became fully vested and paid in cash. The fair value of the equity-classified awards that vested on May 31, 2024 was $102.4 million.

Restricted stock units. Restricted stock units (“RSUs”) are contingent shares that generally vest on either a cliff or graded basis over a one-year, three-year or four-year period (as applicable) and are subject to a service condition. During the nine months ended September 30, 2024, the Company granted 148,325 RSUs to employees and non-employee directors of the Company with a weighted average grant date fair value of $165.59 per share.

Performance share units. Performance share units (“PSUs”) that were granted prior to 2024 are contingent shares that vest on a graded basis over a three-year and four-year period and are subject to a service condition.

2024 Performance share units. During the nine months ended September 30, 2024, the Company granted PSUs that include (i) total stockholder return (“TSR”) PSUs (“Absolute TSR PSUs”) and (ii) relative TSR PSUs (“Relative TSR PSUs” and collectively with the Absolute TSR PSUs, the “2024 PSUs”), which are eligible to vest and become earned at the end of the applicable performance period on December 31, 2026, subject to the level of achievement with respect to certain performance goals.

The Absolute TSR PSUs are subject to time-based service requirements and market conditions based on the TSR achieved by the Company during the performance period. Depending on the Company’s TSR, award recipients may earn between 0% and 300% of the target number of Absolute TSR PSUs originally granted.

The Relative TSR PSUs are subject to time-based service requirements and market conditions based on a comparison of the TSR achieved by the Company against the TSR achieved by the members of a defined peer group at the end of the performance period. Depending on the Company’s TSR performance relative to the TSR performance of the members of the defined peer group, award recipients may earn between 0% and 200% of the target number of Relative TSR PSUs originally granted.

Any earned 2024 PSUs will be settled in shares of the Company’s common stock for up to 100% of the target number of PSUs subject to each applicable award, with any remaining earned PSUs that exceed the target number of PSUs subject to the award being settled in cash based on the fair market value of a share of the Company’s common stock on the applicable payment date. The 2024 PSUs are bifurcated and classified as equity-based and liability-based awards based on the probability of achieving various target performance thresholds.

During the nine months ended September 30, 2024, the Company granted (i) 15,808 Absolute TSR PSUs to employees of the Company with a weighted average grant date fair value of $233.01 per share and (ii) 47,428 Relative TSR PSUs to employees of the Company with a weighted average grant date fair value of $201.02 per share.

Fair value assumptions. The aggregate grant date fair value of the 2024 PSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model which uses a probabilistic approach for estimating the fair value of the awards. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) the yield curve associated with the Company’s credit rating, (iv) implied equity volatility, (v) stock price on the date of grant and, solely for Relative TSR PSUs, (vi) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to the performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the Relative TSR PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.

The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses for the PSUs granted during the periods presented:


	Absolute and Relative TSR PSUs
	Three Months Ended March 31, 2024			Three Months Ended September 30, 2024

Forecast period (years)	3			3
Risk-free interest rates	4.4%			3.8%	—	4.7%
Implied equity volatility	35%			35%

Range of stock price on date of grant	$160.23	—	$163.75	$141.41	—	$169.66

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Leveraged stock units. Leveraged stock units (“LSUs”) are contingent shares granted to certain employees that cliff vest over a three-year and four-year period and are subject to a service condition. No LSUs were granted during the nine months ended September 30, 2024.

Phantom unit awards. Phantom unit awards represent the right to receive a cash payment equal to the fair market value of one share of common stock upon vesting and vest on a graded basis over a three-year period and are subject to a service condition. During the nine months ended September 30, 2024, the Company granted 10,664 phantom unit awards to employees with a weighted average grant date fair value of $163.82 per share.

15. Stockholders’ Equity

Authorized Shares of Common Stock

On May 14, 2024, Chord stockholders approved an amendment to the Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 120,000,000 to 240,000,000 in connection with the Arrangement. This amendment became effective on May 31, 2024.

Issuance of Common Stock

Pursuant to the Arrangement Agreement, each Enerplus common share issued and outstanding immediately prior to the effective time of the Arrangement was converted into the right to receive 0.10125 shares of Chord common stock, par value $0.01 per share. As a result of the completion of the Arrangement on May 31, 2024, the Company issued 20,680,097 shares of common stock to Enerplus shareholders.

Dividends

The following table summarizes the Company’s fixed and variable dividends declared for the nine months ended September 30, 2024 and 2023:


	Rate per Share
	Base		Variable		Total		Total Dividends Declared

							(In thousands)

Q3 2024	$	1.25	$	1.27	$	2.52	$	157,090
Q2 2024	1.25		1.69		2.94		124,708
Q1 2024	1.25		2.00		3.25		137,541
Total	$	3.75	$	4.96	$	8.71	$	419,339


Q3 2023	$	1.25	$	0.11	$	1.36	$	58,374
Q2 2023	1.25		1.97		3.22		137,507
Q1 2023	1.25		3.55		4.80		204,884
Total	$	3.75	$	5.63	$	9.38	$	400,765

Total dividends declared in the table above includes $1.6 million and $5.9 million associated with dividend equivalent rights on unvested equity-based compensation awards for the three and nine months ended September 30, 2024, respectively, and $1.4 million and $10.2 million for the three and nine months ended September 30, 2023, respectively.

On November 6, 2024, the Company declared a base-plus-variable cash dividend of $1.44 per share of common stock. The dividend will be payable on December 12, 2024 to shareholders of record as of November 27, 2024.

Share Repurchase Program

During the nine months ended September 30, 2024, the Company repurchased 1,509,996 shares of common stock at a weighted average price of $157.47 per common share for a total cost of $237.8 million, excluding accrued excise tax of $1.2 million. As of September 30, 2024, there was $445.2 million of capacity remaining under the Company’s $750.0 million share repurchase program.

During the nine months ended September 30, 2023, the Company repurchased 1,023,320 shares of common stock at a weighted average price of $154.52 per common share for a total cost of $158.1 million, excluding accrued excise tax of $0.2 million, under its previous repurchase program, which was replaced by its current $750.0 million share repurchase program.

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In October 2024, the Board of Directors authorized a new share repurchase program of $750.0 million of the Company’s common stock, which replaces the existing $750.0 million share repurchase program. The Company has repurchased, and may repurchase in the future, shares pursuant to a Rule 10b5-1 trading plan under the Securities Exchange Act of 1934, as amended, which permits the Company to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require the Company to make purchases within a particular time frame.

Warrants

As of September 30, 2024, the Company had 1,294,610 warrants outstanding, comprised of (i) 404,058 warrants with an exercise price of $75.57 per share that expire on November 19, 2024 and (ii) 890,552 warrants with an exercise price of $133.70 per share that expire on September 1, 2025. The Company had 395,809 warrants expire on September 1, 2024.

During the three and nine months ended September 30, 2024, there were 922,475 and 1,993,326 warrants exercised, respectively, and during the three and nine months ended September 30, 2023, there were 707,227 and 816,630 warrants exercised, respectively.

16. Earnings Per Share

The Company calculates earnings per share under the two-class method. The Company has granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, the Company computes earnings per share under the two-class earnings allocation method, which computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.

Basic earnings per share amounts have been computed as (i) net income (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations.

The following table summarizes the basic and diluted earnings per share for the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,


	2024		2023		2024		2023
	(In thousands, except per share data)

Net income	$	225,316	$	209,076	$	638,030	$	722,146
Distributed and undistributed earnings allocated to participating securities	(778)		(801)		(2,598)		(2,281)
Net income attributable to common stockholders (basic)	224,538		208,275		635,432		719,865
Reallocation of distributed and undistributed earnings allocated to participating securities	3		28		19		44
Net income attributable to common stockholders (diluted)	$	224,541	$	208,303	$	635,451	$	719,909

Weighted average common shares outstanding:
Basic weighted average common shares outstanding	61,802		41,563		50,388		41,670
Dilutive effect of share-based awards	365		955		413		930
Dilutive effect of warrants	462		1,144		706		927
Diluted weighted average common shares outstanding	62,629		43,662		51,507		43,527

Basic earnings per share	$	3.63	$	5.01	$	12.61	$	17.28
Diluted earnings per share	$	3.59	$	4.77	$	12.34	$	16.54

Anti-dilutive weighted average common shares:
Potential common shares	1,505		3,391		1,853		4,023

For the three and nine months ended September 30, 2024 and 2023, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive.

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17. Commitments and Contingencies

As of September 30, 2024, the Company’s material off-balance sheet arrangements and transactions include $30.7 million in outstanding letters of credit under the Credit Facility and $74.9 million in net surety bond exposure issued as financial assurance on certain agreements.

As of September 30, 2024, there have been no material changes to the Company’s commitments and contingencies disclosed in Note 21 — Commitments and Contingencies in the 2023 Annual Report, other than those assumed in connection with the Arrangement.

Volume commitment agreements. As of September 30, 2024, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 49.7 MMBbl of crude oil, 8.6 MMBbl of NGLs, 492.4 Bcf of natural gas and 0.3 MMBbl of water, prior to any applicable volume credits and within specified timeframes. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed below represent undiscounted cash flows on a gross basis and no inflation elements have been applied.

As of September 30, 2024, the estimable future commitments of the Company’s commitment agreements, including those assumed in connection with the Arrangement, are as follows:


	(In thousands)
Year 1	$	148,397
Year 2	158,177
Year 3	121,161
Year 4	70,441
Year 5	49,671
Thereafter	81,285
	$	629,132

The Company enters into these long-term contracts to provide production flow assurance in oversupplied areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since the amount and timing of any such penalties incurred cannot be predicted with accuracy. For the three and nine months ended September 30, 2024, the Company did not incur any deficiency payments related to these contracts.

The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.

18. Leases

During the three months ended September 30, 2024, the Company recorded a $2.5 million impairment charge related to the Denver office and its related fixed assets acquired in the Arrangement as a result of the current sublease market conditions. There were no lease impairment charges recorded during the six months ended June 30, 2024. During the nine months ended September 30, 2023, the Company recorded a right-of-use asset impairment charge of $17.5 million related to a portion of one of its corporate offices. The right-of-use asset impairment charges are recorded within exploration and impairment on the Condensed Consolidated Statements of Operations.

In connection with the Arrangement, the Company assumed approximately $29.0 million of operating lease liabilities for operating equipment with lease terms through 2027, $7.5 million of operating lease liabilities for office space, primarily in Denver and Calgary, with lease terms through 2029, and approximately $6.5 million of finance lease liabilities for vehicles with lease terms through 2027.

Other than the items disclosed above, no other material changes have occurred to the Company’s lease portfolio for the periods presented. Refer to the 2023 Annual Report for more information on the Company’s leases.

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Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plans” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under “Part II, Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this Quarterly Report on Form 10-Q constitute forward-looking statements.

Forward-looking statements may include statements about:

•crude oil, NGLs and natural gas realized prices;

•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas;

•the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;

•war between Russia and Ukraine as well as war between Hamas and Israel, with the potential for escalation of hostilities across the surrounding countries in the Middle East, and their effect on commodity prices;

•changes in general economic and geopolitical conditions, including as a result of the 2024 U.S. presidential election;

•inflation rates and the impact of associated monetary policy responses, including increased interest rates;

•logistical challenges and supply chain disruptions;

•our business strategy;

•the geographic concentration of our operations;

•estimated future net reserves and present value thereof;

•timing and amount of future production of crude oil, NGLs and natural gas;

•drilling and completion of wells;

•estimated inventory of wells remaining to be drilled and completed;

•costs of exploiting and developing our properties and conducting other operations;

•availability of drilling, completion and production equipment and materials;

•availability of qualified personnel;

•infrastructure for produced and flowback water gathering and disposal;

•gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;

•the possible shutdown of the Dakota Access Pipeline;

•incurring significant transaction and other costs in connection with the Arrangement (as defined in the “Recent Developments” section of Item 2 below) in excess of those anticipated;

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•the ultimate timing, outcome and results of integrating the operations of Chord and Enerplus;

•failure to realize the anticipated benefits or synergies from the Arrangement in the timeframe expected or at all;

•property acquisitions, including the Arrangement, and divestitures;

•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness, including the Arrangement;

•any litigation relating to the Arrangement;

•the amount, nature and timing of capital expenditures;

•availability and terms of capital;

•our financial strategic tactics, budget, projections, execution of business plan and operating results;

•cash flows and liquidity;

•our ability to return capital to shareholders;

•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;

•our ability to comply with the covenants under our Credit Agreement and other indebtedness;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;

•potential effects arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;

•compliance with, and changes in, environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022;

•execution of our ESG initiatives;

•effectiveness of risk management activities;

•competition in the oil and gas industry;

•counterparty credit risk;

•incurring environmental liabilities;

•developments in the global economy as well as any public health crisis similar to or caused by a recurrence of the novel COVID-19 pandemic and resulting demand and supply for crude oil, NGLs and natural gas;

•governmental regulation and the taxation of the oil and gas industry;

•developments in crude oil-producing and natural gas-producing countries;

•technology;

•consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;

•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;

•uncertainty regarding future operating results;

•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;

•the impact of disruptions in the financial markets, including any bank failures and the interest rate environment;

•plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q that are not historical; and

•certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2023 Annual Report and in our other filings with the SEC.

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All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, the proximity to and capacity of transportation facilities and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company”, “Chord”, “we”, “us,” or “our”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

Market Conditions and Commodity Prices

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.

In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of September 30, 2024, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems.

Recent Developments

Enerplus Arrangement

On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement ”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, we agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”). Enerplus was an independent North American oil and gas E&P company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The Arrangement was completed on May 31, 2024.

Upon completion of the Arrangement on May 31, 2024, we issued 20,680,097 shares of common stock and paid $375.8 million in cash to Enerplus shareholders. Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock, par value $0.01 per share, and $1.84 per share in cash in exchange for each share of Enerplus they owned at closing.

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Results of Operations

Comparability of Financial Statements

The results of operations presented below relate to the periods ended September 30, 2024 and 2023. The results reported for the three and nine months ended September 30, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus beginning on May 31, 2024 and the 2023 acquisition of acreage in the Williston Basin, while the results reported for the three and nine months ended September 30, 2023 reflect the consolidated results of Chord, including the 2023 acquisition of acreage in the Williston Basin beginning on June 30, 2023 and excluding the impact from the business combination with Enerplus, unless otherwise noted.

Operational and Financial Highlights

•Production volumes averaged 280,815 Boepd (57% oil), including crude oil volumes of 158,793 Bopd in the third quarter of 2024.

•E&P and other capital expenditures (excluding capitalized interest) were $329.2 million in the third quarter of 2024.

•Lease operating expenses (“LOE”) were $9.56 per Boe in the third quarter of 2024.

•Net cash provided by operating activities was $663.2 million and net income was $225.3 million in the third quarter of 2024.

Shareholder Return Highlights

•Paid $2.52 per share base-plus-variable cash dividend on August 21, 2024.

•Repurchased $146.0 million of common stock in the third quarter of 2024 with $445.2 million remaining under our $750 million share repurchase program.

•In October 2024, the Board of Directors authorized a new $750.0 million share repurchase program.

•Declared a base-plus-variable cash dividend of $1.44 per share of common stock. The dividend will be payable on December 12, 2024 to shareholders of record as of November 27, 2024.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Our revenues for the three and nine months ended September 30, 2024 increased due to the Arrangement, which expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGLs and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

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The following table summarizes our revenues, production and average realized prices for the periods presented:


	Three Months Ended September 30, 2024		Three Months Ended June 30, 2024		Nine Months Ended September 30, 2024		Nine Months Ended September 30, 2023
Revenues (in thousands)
Crude oil revenues	$	1,073,933	$	848,104	$	2,600,888	$	2,074,746
NGL revenues	30,038		36,760		114,055		131,818
Natural gas revenues	17,041		17,803		56,898		95,687
Purchased oil and gas sales	329,455		358,013		1,024,567		629,705

Total revenues	$	1,450,467	$	1,260,680	$	3,796,408	$	2,931,956
Production data
Crude oil (MBbls)	14,609		10,751		34,372		26,653
NGLs (MBbls)	4,758		3,682		11,572		9,541
Natural gas (MMcf)(1)	38,809		26,528		84,428		61,198
Oil equivalents (MBoe)	25,835		18,854		60,015		46,394
Average daily production (Boepd)	280,815		207,187		219,033		169,940
Average daily crude oil production (Bopd)	158,793		118,143		125,445		97,630
Average sales prices
Crude oil (per Bbl)
Average sales price	$	73.51	$	78.89	$	75.67	$	77.84
Effect of derivative settlements(2)	0.07		(0.36)		(0.13)		(7.59)
Average realized price after the effect of derivative settlements(2)	$	73.58	$	78.53	$	75.54	$	70.25
NGLs (per Bbl)
Average sales price	$	6.31	$	9.99	$	9.86	$	13.82
Effect of derivative settlements(2)	—		—		—		0.29
Average realized price after the effect of derivative settlements(2)	$	6.31	$	9.99	$	9.86	$	14.11
Natural gas (per Mcf)
Average sales price(1)	$	0.44	$	0.67	$	0.67	$	1.56
Effect of derivative settlements(2)	—		—		—		(0.11)
Average realized price after the effect of derivative settlements(1)(2)	$	0.44	$	0.67	$	0.67	$	1.45

____________________

(1)For the three and nine months ended September 30, 2024, natural gas production volume from the Marcellus Shale was 10,508 MMcf and 14,272 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $1.32 per Mcf and $1.41 per Mcf, for the three and nine months ended September 30, 2024, respectively.

(2)The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Three months ended September 30, 2024 as compared to three months ended June 30, 2024

Crude oil revenues. Our crude oil revenues increased $225.8 million to $1,073.9 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. Our crude oil revenues increased $283.6 million due to higher total crude oil production volumes sold, primarily due to a full quarter of results from the Arrangement. The increase was partially offset by a decrease of $57.8 million due to lower crude oil realized prices quarter over quarter. Average crude oil sales prices, without derivative settlements, decreased by $5.38 per barrel quarter over quarter to an average of $73.51 per barrel for the three months ended September 30, 2024 primarily due to a decrease in NYMEX WTI.

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NGL revenues. Our NGL revenues decreased $6.7 million to $30.0 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The decrease was primarily due to lower NGL realized prices quarter over quarter resulting in a $13.5 million decrease, partially offset by an increase of $6.8 million due to higher NGL production volumes sold quarter over quarter due to a full quarter of results from the Arrangement. Average NGL sales prices, without derivative settlements, decreased by $3.68 per barrel quarter over quarter to an average of $6.31 per barrel for the three months ended September 30, 2024 primarily due to a decrease in the corresponding NGL product benchmark prices.

Natural gas revenues. Our natural gas revenues decreased $0.8 million to $17.0 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The decrease was primarily due to lower natural gas realized prices quarter over quarter of $6.2 million, offset by an increase in total natural gas production volumes sold of $5.4 million, primarily due to a full quarter of results from the Arrangement. Average natural gas sales prices, without derivative settlements, decreased by $0.23 per Mcf quarter over quarter to $0.44 per Mcf for the three months ended September 30, 2024 primarily due to widening differentials.

Purchased oil and gas sales. Purchased oil and gas sales decreased $28.6 million to $329.5 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. This decrease was primarily due to lower crude oil prices and a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter.

Nine months ended September 30, 2024 as compared to nine months ended September 30, 2023

Crude oil revenues. Our crude oil revenues increased $526.1 million to $2,600.9 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. Our crude oil revenues increased $584.1 million due to higher total crude oil production volumes sold, primarily due to our expanded operations after the Arrangement. The increase was partially offset by a decrease of $57.8 million due to lower crude oil realized prices period over period. Average crude oil sales prices, without derivative settlements, decreased by $2.17 per barrel period over period to an average of $75.67 per barrel for the nine months ended September 30, 2024 primarily due to widening in-basin differentials period over period.

NGL revenues. Our NGL revenues decreased $17.8 million to $114.1 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The decrease was primarily due to lower NGL realized prices period over period resulting in a $37.8 million decrease, partially offset by an increase of $20.0 million due to higher NGL production volumes sold period over period. Average NGL sales prices, without derivative settlements, decreased by $3.96 per barrel period over period to an average of $9.86 per barrel for the nine months ended September 30, 2024 primarily due to wider differentials on incremental volumes from the Arrangement period over period.

Natural gas revenues. Our natural gas revenues decreased $38.8 million to $56.9 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The decrease was primarily due to lower natural gas realized prices period over period of $54.5 million, offset by an increase in total natural gas production volumes sold of $15.6 million, primarily due to our expanded operations after the Arrangement. Average natural gas sales prices, without derivative settlements, decreased by $0.89 per Mcf period over period to $0.67 per Mcf for the nine months ended September 30, 2024 primarily due to the impact of incurring a fixed fee for the majority of our natural gas marketing contracts beginning in the second quarter of 2023.

Purchased oil and gas sales. Purchased oil and gas sales increased $394.9 million to $1,024.6 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices period over period.

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Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:


	Three Months Ended September 30, 2024		Three Months Ended June 30, 2024		Nine Months Ended September 30, 2024		Nine Months Ended September 30, 2023


	(In thousands, except per Boe of production data)
Operating expenses
Lease operating expenses	$	247,055	$	176,647	$	582,908	$	489,077
Gathering, processing and transportation expenses	77,353		63,130		194,467		132,706
Purchased oil and gas expenses	329,622		356,356		1,021,739		627,433
Production taxes	100,973		79,522		244,410		191,490
Depreciation, depletion and amortization	360,214		227,928		757,036		431,131
General and administrative expenses	52,115		82,077		159,904		100,775
Exploration and impairment	7,269		1,485		14,908		33,257

Total operating expenses	1,174,601		987,145		2,975,372		2,005,869
Gain (loss) on sale of assets, net	(2,973)		15,486		13,814		3,739
Operating income	272,893		289,021		834,850		929,826
Other income (expense)
Net gain on derivative instruments	52,721		4,608		29,753		11,247
Net gain from investment in unconsolidated affiliate	1,089		5,862		23,246		21,421
Interest expense, net of capitalized interest	(19,146)		(12,208)		(38,946)		(22,286)
Other income (expense)	(2,657)		4,081		4,253		9,137
Total other income (expense), net	32,007		2,343		18,306		19,519
Income before income taxes	304,900		291,364		853,156		949,345
Income tax expense	(79,584)		(78,003)		(215,126)		(227,199)
Net income	$	225,316	$	213,361	$	638,030	$	722,146


Costs and expenses (per Boe of production)
Lease operating expenses	$	9.56	$	9.37	$	9.71	$	10.54
Gathering, processing and transportation expenses	2.99		3.35		3.24		2.86
Production taxes	3.91		4.22		4.07		4.13

Three months ended September 30, 2024 as compared to three months ended June 30, 2024

Lease operating expenses. LOE increased $70.4 million to $247.1 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024 primarily due to increased costs resulting from the Arrangement of $59.7 million and increased fixed costs quarter over quarter of $10.8 million. LOE per Boe increased $0.19 per Boe quarter over quarter to $9.56 per Boe for the three months ended September 30, 2024 primarily due to higher fixed costs.

Gathering, processing and transportation expenses. GPT expenses increased $14.2 million to $77.4 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024 primarily due to increased costs resulting from the Arrangement of $24.4 million, partially offset by lower transportation expenses due to a fixed-cost oil transportation contract that terminated during the second quarter of 2024. GPT expenses per Boe decreased $0.36 per Boe to $2.99 per Boe for the three months ended September 30, 2024 primarily due to the termination of the fixed-cost oil transportation contract during the second quarter of 2024.

Purchased oil and gas expenses. Purchased oil and gas expenses decreased $26.7 million to $329.6 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024 primarily due to lower crude oil prices and a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter.

Production taxes. Production taxes increased $21.5 million to $101.0 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The increase was primarily due to a $26.0 million increase in production taxes attributable to our expanded operations after the Arrangement, partially offset by the impact of lower oil prices quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas sales of 9.0% for the three months ended September 30, 2024 was in line with the production tax rate of 8.8% for the three months ended June 30, 2024.

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Depreciation, depletion and amortization. DD&A expense increased $132.3 million to $360.2 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The increase was primarily due to an $86.1 million increase in DD&A expenses attributable to our expanded operations after the Arrangement, an increase of $40.1 million due to a higher depletion rate quarter over quarter and an increase of $5.6 million due to higher production volumes quarter over quarter. The depletion rate increased $1.82 per Boe quarter over quarter to $13.65 per Boe for the three months ended September 30, 2024 primarily due to the higher costs attributable to the oil and gas properties acquired in the Arrangement.

General and administrative expenses. G&A expenses decreased $30.0 million to $52.1 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The decrease was primarily attributable to a decrease in merger-related costs of $37.2 million, partially offset by an increase in compensation and other costs associated with a larger organization after the Arrangement of $7.2 million.

Exploration and impairment. Exploration and impairment expenses increased $5.8 million to $7.3 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The increase is primarily due to a $3.5 million lower of cost or net realizable value write-down of oil-in-tank inventory and a $2.5 million write-down of our Denver office lease acquired in connection with the Arrangement.

Gain (loss) on sale of assets, net. During the three months ended September 30, 2024 and June 30, 2024, we recorded a net loss on sale of assets of $3.0 million and a net gain on sale of assets of $15.5 million, respectively, primarily related to the divestitures of certain non-operated properties within each quarter.

Derivative instruments. We recorded a $52.7 million net gain on derivative instruments for the three months ended September 30, 2024, which was comprised of a net gain of $54.1 million associated with our commodity derivative contracts, offset by an unrealized loss of $1.4 million associated with a contract that includes contingent consideration. The net gain of $54.1 million on commodity derivative contracts included an unrealized gain of $53.2 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices and a realized gain of $1.0 million on settled commodity derivative contracts. During the three months ended June 30, 2024, we recorded a $4.6 million net gain on derivative instruments, which was comprised of a net gain of $4.0 million associated with our commodity derivative contracts and an unrealized gain of $0.6 million associated with a contract that includes contingent consideration. The net gain of $4.0 million on commodity derivative contracts included an unrealized gain of $7.9 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $3.9 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $1.1 million gain related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended September 30, 2024 due to a gain of $2.3 million for a cash distribution received from Energy Transfer, offset by an unrealized loss of $1.2 million as a result of a decrease in the fair value of the investment during the quarter. During the three months ended June 30, 2024, we recorded a $5.9 million gain related to our investment in Energy Transfer due to an unrealized gain of $3.6 million as a result of an increase in the fair value of the investment during the quarter, coupled with a gain of $2.3 million for a cash distribution received from Energy Transfer during the quarter.

Interest expense, net of capitalized interest. Interest expense increased $6.9 million to $19.1 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The increase was primarily due to higher borrowings on our revolving Credit Facility during the quarter. For the three months ended September 30, 2024, the weighted average borrowings outstanding under the Credit Facility were $567.6 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.51%. For the three months ended June 30, 2024, the weighted average borrowings outstanding under the Credit Facility were $230.0 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.53%. Interest capitalized during the three months ended September 30, 2024 and June 30, 2024 was $1.8 million and $1.2 million, respectively.

Nine months ended September 30, 2024 as compared to nine months ended September 30, 2023

Lease operating expenses. LOE increased $93.8 million to $582.9 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $105.5 million of additional LOE period over period, increased variable costs of $16.0 million, and increased fixed costs of $5.9 million. These costs were partially offset by a decrease in workover activity of $33.6 million period over period. LOE per Boe decreased $0.83 per Boe period over period to $9.71 per Boe for the nine months ended September 30, 2024 primarily due to higher production volumes and lower workover costs.

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Gathering, processing and transportation expenses. GPT expenses increased $61.8 million to $194.5 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $45.8 million of additional GPT and lower fair value gains of $22.7 million attributable to the completion of certain derivative transportation contracts during the nine months ended September 30, 2024. These increases resulted in an increase in GPT expenses of $0.38 per Boe period over period to $3.24 per Boe for the nine months ended September 30, 2024.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $394.3 million to $1,021.7 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023 primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices period over period.

Production taxes. Production taxes increased $52.9 million to $244.4 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase was primarily due to an overall increase in oil production volumes period over period and included a $48.2 million increase in production taxes attributable to our expanded operations after the Arrangement. The production tax rate as a percentage of crude oil, NGL and natural gas sales increased to 8.8% for the nine months ended September 30, 2024 as compared to 8.3% for the nine months ended September 30, 2023. This rate increase period over period was primarily due to decreased natural gas and NGL revenues as a result of lower realized prices.

Depreciation, depletion and amortization. DD&A expense increased $325.9 million to $757.0 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $167.0 million of additional DD&A expense period over period, an increase of $151.2 million due to a higher depletion rate period over period and an increase of $9.1 million due to higher production volumes period over period. The depletion rate increased $3.28 per Boe period over period to $12.30 per Boe for the nine months ended September 30, 2024 primarily due to the higher costs attributable to the oil and gas properties acquired in the Arrangement.

General and administrative expenses. G&A expenses increased $59.1 million to $159.9 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023 primarily due to increased merger-related costs of $70.6 million and an increase in costs associated with a larger organization after the Arrangement of $15.8 million. These increases were partially offset by a decrease in stock-based compensation costs of $21.2 million due to the vesting of certain equity-based compensation awards period over period.

Exploration and impairment. Exploration and impairment expenses decreased $18.3 million to $14.9 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. During the nine months ended September 30, 2024, we recorded an impairment expense of $9.8 million, which primarily included a $7.4 million lower of cost or net realizable value write-down of oil-in-tank inventory and a $2.5 million impairment expense related to the Denver office lease and related fixed assets acquired in connection with the Arrangement. During the nine months ended September 30, 2023, exploration and impairment expenses totaled $33.3 million, which was primarily due to impairment expenses of $29.0 million, including $17.5 million associated with the write-down of our Denver office lease acquired in 2022, $5.8 million associated with a lower of cost or net realizable value write-down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.

Gain (loss) on sale of assets, net. During the nine months ended September 30, 2024 and 2023, we recorded a net gain on sale of assets of $13.8 million and $3.7 million, respectively, primarily related to the divestitures of certain non-operated properties within each period.

Derivative instruments. During the nine months ended September 30, 2024, we recorded a $29.8 million net gain on derivative instruments, which was comprised of a net gain of $27.1 million associated with our commodity derivative contracts and an unrealized gain of $2.6 million associated with a contract that includes contingent consideration. The net gain of $27.1 million on commodity derivative contracts included an unrealized gain of $31.5 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices and a realized loss of $4.3 million on settled commodity derivative contracts. During the nine months ended September 30, 2023, we recorded an $11.2 million net gain on derivative instruments, which was primarily comprised of a net gain of $7.2 million associated with a contract that includes contingent consideration and a net gain of $4.1 million associated with commodity derivative contracts. The net gain of $4.1 million on commodity derivative contracts included an unrealized gain of $210.3 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $206.2 million on settled commodity derivative contracts.

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Investment in unconsolidated affiliate. We recorded a $23.2 million gain related to our investment in Energy Transfer for the nine months ended September 30, 2024, which included an unrealized gain of $16.3 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $6.9 million for cash distributions received from Energy Transfer during the period. During the nine months ended September 30, 2023, we recorded a gain of $21.4 million related to our investment in Energy Transfer, which primarily included an unrealized gain of $10.8 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $8.5 million for cash distributions received from Energy Transfer during the period.

Interest expense, net of capitalized interest. Interest expense increased $16.7 million to $38.9 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase is primarily due to higher borrowings outstanding on our revolving Credit Facility during the period. For the nine months ended September 30, 2024, the weighted average borrowings outstanding under the Credit Facility were $267.0 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.51%. For the nine months ended September 30, 2023, the weighted average borrowings outstanding under the Credit Facility were $3.3 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.09%. Interest capitalized during the nine months ended September 30, 2024 and September 30, 2023 was $3.7 million and $3.6 million, respectively.

Income tax expense. Our effective tax rate was recorded at 25.2% and 23.9% of pre-tax income for the nine months ended September 30, 2024 and September 30, 2023, respectively. Our effective tax rate was higher period over period due to Canadian losses for which no benefit is recognized and deferred taxes on unremitted earnings.

Liquidity and Capital Resources

As of September 30, 2024, we had $1.1 billion of liquidity available, including $52.1 million in cash and cash equivalents and $999.3 million of aggregate unused borrowing capacity available under our Credit Facility (defined below). Our primary sources of liquidity were from cash on hand, cash flows from operations and available borrowing capacity under our Credit Facility. Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments, share repurchases, cash consideration and transaction costs associated with the Arrangement, and working capital requirements.

Capital availability will be affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of ESG matters and other factors, many of which are beyond our control. The U.S. Federal Reserve recently decreased interest rates, however the potential for such rates to decrease further or to remain elevated for an extended period of time has created additional economic uncertainty. Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

Enerplus Arrangement. In connection with the consummation of the Arrangement on May 31, 2024, we paid $375.8 million, or $1.84 per Enerplus common share, to Enerplus shareholders. In addition, we paid $395.0 million to settle Enerplus’ revolving bank credit facility balance and $102.4 million to settle all outstanding Enerplus equity-based compensation awards.

Also in connection with the Arrangement, we incurred certain costs for advisory, legal and other third-party fees which were recorded to G&A expenses on the Condensed Consolidated Statements of Operations. During the three and nine months ended September 30, 2024, we incurred merger-related costs of $17.5 million and $80.3 million, respectively, primarily related to legal and advisory services and severance costs.

Our cash flows depend on many factors, including the price of crude oil, NGLs and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices.

Commodity derivative contracts. As of September 30, 2024, our commodity derivative contracts cover 2,668 MBbls of our crude oil production for 2024, 7,111 MBbls of our crude oil production and 5,681,600 MMBtu of our natural gas production for 2025 and 2,540 MBbls of our crude oil production and 2,262,500 MMBtu of our natural gas production for 2026. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.

In October 2024, we entered into new commodity derivative contracts to manage risks related to changes in crude oil prices. The following table summarizes these commodity derivative contracts:

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			Volumes (Bbl)		Weighted Average Prices
Commodity	Settlement Period	Derivative Instrument	Total	Daily	Fixed-price Swaps		Floor		Ceiling
Crude oil	2025	Two-way collars	730,000	2,000			$	65.00	$	76.62
Crude oil	2025	Fixed-price swaps	730,000	2,000	$	71.87
Crude oil	2026	Two-way collars	730,000	2,000			$	65.00	$	71.83

We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. We believe that for the substantial majority of these agreements our future production will be adequate to meet our delivery commitments or that we will be able to purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments. For the three and nine months ended September 30, 2023, we did not incur any deficiency payments related to these contracts. See “Item 1. Financial Statements (Unaudited)—Note 17—Commitments and Contingencies” for additional information on our volume delivery commitments.

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases. On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

Revolving credit facility. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $3.0 billion and elected commitments of $1.5 billion that is due July 1, 2027. As of September 30, 2024, we had $470.0 million borrowings outstanding and $30.7 million of outstanding letters of credit, resulting in an unused borrowing capacity of $999.3 million. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. We were in compliance with the financial covenants under the Credit Facility as of September 30, 2024. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information.

Senior unsecured notes. As of September 30, 2024, we had $400.0 million of 6.375% senior unsecured notes outstanding (the “Senior Notes”) that mature on June 1, 2026. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information.

Enerplus senior unsecured notes. In connection with the Arrangement on May 31, 2024, we assumed $63.0 million of 3.79% senior unsecured notes from Enerplus (the “Enerplus Senior Notes”). On July 2, 2024, we repaid all of the remaining outstanding Enerplus Senior Notes and $0.8 million of accrued interest on such notes.

Cash Flows

Our cash flows for the nine months ended September 30, 2024 and 2023 are presented below:


	Nine Months Ended September 30,
	2024		2023

	(In thousands)
Net cash provided by operating activities	$	1,530,772	$	1,276,517
Net cash used in investing activities	(1,494,111)		(1,112,318)
Net cash used in financing activities	(302,609)		(492,384)
Decrease in cash and cash equivalents	$	(265,948)	$	(328,185)

Cash flows provided by operating activities

Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $1,530.8 million for the nine months ended September 30, 2024. The increase in net cash provided by operating activities of $254.3 million as compared to the nine months ended September 30, 2023 was primarily due to an increase in oil revenues, offset by increases in LOE, merger-related costs, GPT costs and production taxes, as well as changes in our working capital. See “Results of Operations” above for additional information.

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Working Capital. Our working capital is primarily impacted by the factors discussed above, coupled with the timing of cash receipts and disbursements. During the nine months ended September 30, 2024 and 2023, changes in working capital (as reflected in the Condensed Consolidated Statements of Cash Flows) increased net cash flows from operating activities by $23.3 million and decreased net cash flows from operating activities by $84.3 million, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $999.3 million as of September 30, 2024, and excludes current hedge assets, which were $55.7 million as of September 30, 2024. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were immaterial as of September 30, 2024.

Cash flows used in investing activities

For the nine months ended September 30, 2024, net cash used in investing activities of $1,494.1 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $877.4 million and net cash paid for the Arrangement of $652.7 million. The net cash used in the Arrangement included $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders and $102.4 million paid to settle Enerplus’ equity awards, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities during the nine months ended September 30, 2024 also included the receipt of the 2023 contingent consideration earn-out payment of $25.0 million and proceeds from divestitures of $21.8 million. Net cash used in investing activities for the nine months ended September 30, 2023 of $1,112.3 million was primarily attributable to $642.6 million of capital expenditures, $361.6 million paid for the 2023 acquisition of acreage in the Williston Basin and $203.2 million associated with the settlement of derivative contract, partially offset by $46.0 million of proceeds from divestitures and $40.6 million of proceeds from the sale of Energy Transfer units.

Cash flows used in financing activities

For the nine months ended September 30, 2024, net cash used in financing activities of $302.6 million was primarily attributable to dividends paid to shareholders of $437.7 million, payments to repurchase our common stock of $239.8 million, repayments on our Enerplus Senior Notes of $63.0 million and payments for income tax withholdings on vested equity-based compensation awards of $58.0 million. These uses of cash were partially offset by borrowings under the Credit Facility of $2.3 billion, partially offset by repayments of $1.8 billion, resulting in net borrowings under the Credit Facility of $0.5 billion, primarily made in connection with the Arrangement, and proceeds from the exercise of outstanding warrants of $30.5 million. Net cash used in financing activities for the nine months ended September 30, 2023 of $492.4 million was primarily attributable to dividends paid to shareholders of $394.7 million, payments to repurchase our common stock of $157.1 million and payments for income tax withholdings on vested equity-based compensation awards of $13.8 million, partially offset by proceeds from the exercise of outstanding warrants of $74.6 million.

Capital Expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table:


	Three Months Ended						Nine Months Ended
	March 31, 2024		June 30, 2024		September 30, 2024		September 30, 2024

	(In thousands)
E&P	$	257,712	$	312,882	$	328,429	$	899,023
Other capital expenditures(1)(5)	745		2,586		2,596		5,927
Total E&P and other capital expenditures(2)	258,457		315,468		331,025		904,950
Acquisitions(3)	—		6,589		7,011		13,600
Total capital expenditures(2)(4)	$	258,457	$	322,057	$	338,036	$	918,550

(1)Other capital expenditures include items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $1.8 million and $3.7 million for the three and nine months ended September 30, 2024, respectively.

(2)Total capital expenditures for the nine months ended September 30, 2024 include approximately $20.0 million related to certain non-operated divested assets that are expected to be reimbursed.

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(3)Excludes amounts attributable to the Arrangement, including cash consideration of $375.8 million.

(4)Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

(5)For the three and nine months ended September 30, 2024, capital expenditures related to the Marcellus Shale were $5.2 million and $7.3 million, respectively.

Dividends

On November 6, 2024, we declared a base-plus-variable cash dividend of $1.44 per share of common stock. The dividend will be payable on December 12, 2024 to shareholders of record as of November 27, 2024. See “Item 1. Financial Statements (Unaudited)—Note 15—Stockholders’ Equity” for additional information.

See “Part II. Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Return of Capital Plan” in our 2023 Annual Report for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

During the nine months ended September 30, 2024, we repurchased 1,509,996 shares of common stock at a weighted average price of $157.47 per common share for a total cost of $237.8 million, excluding accrued excise tax of $1.2 million, under our $750 million share repurchase program. In October 2024, our Board of Directors authorized a new share repurchase program of $750 million, which replaces the existing $750 million share repurchase program. As of September 30, 2024, there was $445.2 million of capacity remaining under the previous $750 million share repurchase program.

During the nine months ended September 30, 2023, we repurchased 1,023,320 shares of common stock under our previous share repurchase program, which was replaced by our current $750 million share repurchase program.

Fair Value of Financial Instruments

See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information on our derivative instruments and their related fair value measurements. See also “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2023 Annual Report, except as follows.

Business combinations. We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions in the Arrangement relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of crude oil, NGL and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation as described in Item 1. Financial Statements (Unaudited)—Note 1—Organization and Summary of Significant Accounting Policies—Goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Item 3. — Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks, including commodity price risk, interest rate risk, counterparty and customer risk and inflation risk. We address these risks through a program of risk management, including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in crude oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk derivative instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2023 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several years, and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGLs and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our unaudited condensed consolidated balance sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” and “Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

The fair value of our unrealized crude oil derivative positions at September 30, 2024 was a net asset position of $37.9 million. A 10% increase in crude oil prices would reduce the fair value of this unrealized derivative asset position by approximately $48.8 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $49.5 million. The fair value of our unrealized natural gas derivative positions at September 30, 2024 was a net asset position of $1.5 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative asset position by approximately $2.2 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $2.2 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

In addition, in connection with the 2021 divestiture of certain oil and gas properties, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. If the NYMEX WTI crude oil price for calendar year 2024 is less than $45 per barrel, then our right to receive any remaining earn-out payments is terminated. As of September 30, 2024, the fair value of this contingent consideration was $45.3 million. During the nine months ended September 30, 2024, we received $25.0 million related to the 2023 earn-out payment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information.

Interest rate risk. At September 30, 2024, we had $400.0 million of senior unsecured notes at a fixed interest rate of 6.375% per annum. At September 30, 2024, we had $470.0 million borrowings and $30.7 million of outstanding letters of credit issued under the Credit Facility. Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). As of September 30, 2024, if interest rates were to increase by 100 basis points on the Credit Facility, the impact on our annual interest expense would not be material. See “Item 1. Financial Statements (Unaudited)—Note 11—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

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We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the three and nine months ended September 30, 2024, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial position and related financial results.

We monitor our exposure to counterparties on crude oil, NGL and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial.

In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

Item 4. — Controls and Procedures

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2024. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of September 30, 2024.

On May 31, 2024, we completed the Arrangement. Management’s assessment and conclusion on the effectiveness of our internal control over financial reporting as of September 30, 2024 excludes an assessment of the internal control over financial reporting of Enerplus.

Changes in internal control over financial reporting

On May 31, 2024, we completed the Arrangement. As part of the ongoing integration, we are in the process of incorporating the controls and related procedures of Enerplus. Other than incorporating Enerplus’ controls, there were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

See “Part I, Item 1. — Financial Statements (Unaudited)—Note 17—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings.

Item 1A. — Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report on Form 10-Q and our other SEC filings could have a material impact on our business, financial position, results of operations or cash flows. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in “Part I. Item 1A. Risk Factors” in our 2023 Annual Report. There have been no material changes in our risk factors from those described in our 2023 Annual Report, except as described below.

The SEC’s Final Rules on The Enhancement and Standardization of Climate-Related Disclosures could result in increased compliance risks and costs.

The SEC released its final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks, management and governance practices, and financial impacts, as well as greenhouse gas emissions. Large accelerated filers will be required to incorporate the applicable climate-related disclosures into their filings beginning in fiscal year 2025, with additional requirements relating to the disclosure of Scope 1 and 2 greenhouse gas emissions, if material, and attestation reports for certain large accelerated filers subsequently phasing in. Refer to “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” in our 2023 Annual Report for prior discussion of the SEC’s then-proposed rule. While we are still assessing our obligations under the rule, complying with such obligations may result in increased costs and SEC or investor scrutiny of our disclosures. The SEC has paused implementation of the final rule pending the resolution of consolidated legal challenges that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. The outcome of this litigation may reduce or expand our obligations under the final rule.

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Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered sales of equity securities. There were no sales of unregistered equity securities during the period covered by this report.

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended September 30, 2024:


Period	Total Number of Shares Exchanged(1)(2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs(2)(3)
July 1 – July 31, 2024	361,587	$	171.85	360,255	$	529,353,310
August 1 – August 31, 2024	262,770	154.21		260,496	489,221,431
September 1 – September 30, 2024	330,666	133.04		330,666	445,228,280
Total	955,023	$	153.56	951,417

___________________

(1)During the third quarter of 2024, we withheld 3,606 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.

(2)During the third quarter of 2024, we repurchased 951,417 shares of our common stock at a weighted average price of $153.50 per common share for a total cost of $146.0 million, excluding accrued excise tax of $1.2 million, under our publicly announced share repurchase program.

(3)Our Board of Directors had previously authorized a share repurchase program of up to $750 million of our common stock. In October 2024, the Board of Directors authorized a new share repurchase program covering up to $750 million of common stock, which replaces the existing $750 million share repurchase program.

Item 5. — Other Information

Rule 10b5-1 trading arrangements. During the fiscal quarter ended September 30, 2024, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

Item 6. — Exhibits


Exhibit No.						Description of Exhibit

2.1						Arrangement Agreement, dated as of February 21, 2024, by and among Chord Energy Corporation, Spark Acquisition ULC and Enerplus Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on February 26, 2024, and incorporated herein by reference).



3.1						Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Chord Energy Corporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on June 6, 2024, and incorporated herein by reference).

4.1						Third Supplemental Indenture to Indenture dated June 28, 2024, by and among Chord Energy Corporation, the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q on August 8, 2024, and incorporated herein by reference).

4.2						First Amendment to the Chord Energy Corporation Long Term Incentive Plan (filed as Exhibit 4.3 to the Company's Registration Statement on Form S-8 on September 13, 2024, and incorporated herein by reference).

10.1						Fifth Amendment to the Amended and Restated Credit Agreement, dated as of May 31, 2024, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 6, 2024, and incorporated herein by reference).

10.2						Sixth Amendment to the Amended and Restated Credit Agreement, dated as of November 4, 2024, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto.

31.1(a)						Sarbanes-Oxley Section 302 certification of Principal Executive Officer.

31.2(a)						Sarbanes-Oxley Section 302 certification of Principal Financial Officer.

32.1(b)						Sarbanes-Oxley Section 906 certification of Principal Executive Officer.

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32.2(b)						Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

101.INS(a)						XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH(a)						XBRL Schema Document.

101.CAL(a)						XBRL Calculation Linkbase Document.

101.DEF(a)						XBRL Definition Linkbase Document.

101.LAB(a)						XBRL Label Linkbase Document.

101.PRE(a)						XBRL Presentation Linkbase Document.

104(a)						Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

___________________

(a)Filed herewith.

(b)Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CHORD ENERGY CORPORATION

Date:

November 7, 2024

By:

/s/ Daniel E. Brown

Daniel E. Brown

President and Chief Executive Officer
(Principal Executive Officer)

By:

/s/ Richard N. Robuck

Richard N. Robuck

Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)

Execution Version


Sixth Amendment To Amended and Restated Credit Agreement Dated as of November 4, 2024 Among Chord Energy Corporation, as Parent, Oasis Petroleum North America LLC, As Borrower, the other Credit Parties party hereto, Wells Fargo Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender and The Lenders Party Hereto

SIXTH AMENDMENT TO
AMENDED AND RESTATED CREDIT AGREEMENT

THIS SIXTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this “Sixth Amendment”) dated as of November 4, 2024, is among: Chord Energy Corporation, a Delaware corporation (the “Parent”); Chord Energy LLC, a Delaware limited liability company (f/k/a Oasis Petroleum LLC) (“Chord LLC”), Oasis Petroleum North America LLC, a Delaware limited liability company (the “Borrower”); the other Guarantors listed on the signature pages hereto; each of the Lenders party hereto; and Wells Fargo Bank, National Association, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”) and as the issuing bank (in such capacity, the “Issuing Bank”).

R E C I T A L S:

A.The Parent, Chord LLC, the Borrower, the Administrative Agent and the Lenders are parties to that certain Amended and Restated Credit Agreement dated as of July 1, 2022 (as amended, amended and restated, restated, supplemented or otherwise modified prior to the date hereof, the “Credit Agreement”), pursuant to which the Lenders have made certain extensions of credit available to and on behalf of the Borrower.

B.The Parent, the Borrower, the Administrative Agent, the Issuing Bank and the Lenders party hereto desire to amend certain provisions of the Credit Agreement as set forth herein effective as of the Sixth Amendment Effective Date (as defined below), subject to the terms and conditions hereof.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Sixth Amendment. Unless otherwise indicated, all section references in this Sixth Amendment refer to sections of the Credit Agreement.

Section 2.Amendments to Credit Agreement. In reliance on the representations, warranties, covenants and agreements contained in this Sixth Amendment, and subject to the conditions precedent contained in Section 3 hereof, effective as of the Sixth Amendment Effective Date, the Credit Agreement shall be amended as follows:

2.1Amendments to Section 1.02.

(a)Each of the following definitions is hereby amended and restated in its entirety to read as follows:

“Agreement” means this Amended and Restated Credit Agreement, including any schedules and exhibits hereto, as amended by the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, and the Sixth Amendment, and as the same may from time to time be further amended, restated, amended and restated, supplemented or modified.

(b)Each of the following definitions is hereby added to Section 1.02 in its appropriate alphabetical order to read as follows:

“Sixth Amendment” means that certain Sixth Amendment to Amended and Restated Credit Agreement, dated as of November 4, 2024 among the Parent, the Borrower, the other Guarantors, the Administrative Agent, the Issuing Bank and the Lenders party thereto.

2.2Amendment to Section 9.02(c). Section 9.02(c) is hereby amended by replacing the phrase “incurred on or prior to December 1, 2024” contained therein with the phrase “incurred on or prior to December 1, 2025”.

Section 3.Conditions Precedent. This Sixth Amendment shall become effective as of the date when each of the following conditions is satisfied (or waived in accordance with Section 12.02 of the Credit Agreement) (the “Sixth Amendment Effective Date”):

3.1Executed Counterparts of Sixth Amendment. The Administrative Agent shall have received from the Borrower, each Guarantor and the Majority Lenders (in such number as may be requested by the Administrative Agent) executed counterparts of this Sixth Amendment signed on behalf of such Person.

3.2Fees and Expenses. The Administrative Agent shall have received all fees and other amounts due and payable by the Credit Parties on or prior to the Sixth Amendment Effective Date, including, to the extent invoiced at least two (2) Business Days prior to the Sixth Amendment Effective Date, reimbursement or payment of all reasonable out-of-pocket expenses required to be reimbursed or paid by the Borrower pursuant to the Credit Agreement.

3.3No Default. No Default, Event of Default or Borrowing Base Deficiency shall have occurred and be continuing as of the Sixth Amendment Effective Date prior to and after giving effect to the terms of this Sixth Amendment.

The Administrative Agent is hereby authorized and directed to declare the Sixth Amendment Effective Date to have occurred when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 or the waiver of such conditions as permitted hereby. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.

Section 4.Miscellaneous.

4.1Confirmation and Effect. The provisions of the Credit Agreement, as amended by this Sixth Amendment, shall remain in full force and effect following the effectiveness of this Sixth Amendment. Each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein” or any other word or words of similar import shall mean and be a reference to the Credit Agreement as amended hereby, and each reference in any other Loan Document to the Credit Agreement or any word or words of similar import shall be and mean a reference to the Credit Agreement as amended hereby.

4.2No Waiver. Neither the execution by the Administrative Agent or the Lenders of this Sixth Amendment, nor any other act or omission by the Administrative Agent or the Lenders or their officers in connection herewith, shall be deemed a waiver by the Administrative Agent or the Lenders of any Defaults or Events of Default which may exist, which may have occurred prior to the date of the effectiveness of this Sixth Amendment or which may occur in the future under the Credit Agreement and/or the other Loan Documents. Similarly, nothing contained in this Sixth Amendment shall directly or indirectly in any way whatsoever either: (a) impair, prejudice or otherwise adversely affect the Administrative Agent’s or the Lenders’ right at any time to exercise any right, privilege or remedy in connection with the Loan Documents with respect to any Default or Event of Default, (b) except to the extent expressly set forth herein, amend or alter any provision of the Credit Agreement, the other Loan Documents, or any other contract or instrument, or (c) constitute any course of dealing or other basis for altering any obligation of the Borrower or any right, privilege or remedy of the Administrative Agent or the Lenders under the Credit Agreement, the other Loan Documents, or any other contract or instrument.

4.3Ratification and Affirmation; Representations and Warranties. Each Credit Party hereby: (a) acknowledges the terms of this Sixth Amendment, (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby and (c) represents and warrants to the Lenders that as of the date hereof, after giving effect to the execution of this Sixth Amendment: (i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (or, if already qualified by materiality, Material Adverse Effect or a similar qualification, true and correct in all respects), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects (or, if already qualified by materiality, Material Adverse Effect or a similar qualification, true and correct in all respects) as of such specified earlier date and (ii) no Default or Event of Default has occurred and is continuing.

4.4Counterparts. This Sixth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Sixth Amendment by facsimile or other electronic transmission (e.g., “pdf” or “tif”), including via DocuSign or other similar electronic signature technology shall be effective as delivery of a manually executed counterpart hereof.

4.5No Oral Agreement. This Sixth Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties. There are no subsequent oral agreements between the parties.

4.6GOVERNING LAW. THIS SIXTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

4.7Payment of Expenses. In accordance with Section 12.03 of the Credit Agreement, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of-pocket costs and reasonable expenses incurred in connection with this Sixth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of Simpson Thacher & Bartlett LLP, as counsel to the Administrative Agent.

4.8Severability. Any provision of this Sixth Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

4.9Successors and Assigns. This Sixth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

4.10Loan Document. This Sixth Amendment shall constitute a “Loan Document” under and as defined in Section 1.02 of the Credit Agreement.

4.11No Novation. The parties hereto agree that this Sixth Amendment does not in any way constitute a novation of the existing Credit Agreement, but is an amendment of the Credit Agreement.

[Signatures Begin Next Page]

IN WITNESS WHEREOF, the parties hereto have caused this Sixth Amendment to be duly executed as of the date first written above.


BORROWER:	OASIS PETROLEUM NORTH AMERICA LLC


	By:	/s/ Richard Robuck
	Name:	Richard Robuck
	Title:	Executive Vice President and Chief Financial Officer


GUARANTORS:	CHORD ENERGY CORPORATION
	CHORD ENERGY LLC
	CHORD ENERGY MARKETING LLC
	OASIS WELL SERVICES LLC
	OMS HOLDINGS LLC
	OASIS PETROLEUM PERMIAN LLC
	OASIS INVESTMENT HOLDINGS LLC
	WHITING HOLDINGS LLC
	WHITING OIL AND GAS CORPORATION
	SPARK CANADIAN HOLDINGS INC.
	SPARK ACQUISITION ULC
	ENERPLUS CORPORATION
	ENERPLUS ENERGY LTD.
	ENERPLUS RESOURCES U.S. INC.
	ENERPLUS USA 2006 ACQUISITION INC.
	ENERPLUS RESOURCES (USA)
	CORPORATION
	ENERPLUS WILLISTON I, LLC
	ENERPLUS WILLISTON II, LLC

	By:	/s/ Richard Robuck
	Name:	Richard Robuck
	Title:	Executive Vice President and Chief Financial Officer